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Hot water extraction and cold water injection into an underground geothermal reservoir cause mechanical deformation of rock matrix and rock joints/fractures. That leads to alteration of hydraulic transmissivity. To study the evolution of reservoir transmissivity we performed coupled Thermo-Hydro-Mechanical (THM) simulations using a robust code called Finite Element for Heat and Mass Transfer (FEHM) for a 3-D domain with a single fracture connecting the injection and production wells. Rock fracture was modeled as a thin equivalent porous medium. We established dynamic relations between the properties of the equivalent porous medium and fracture aperture. In this paper we discuss the alteration of fracture aperture due to heat extraction. The channeling of flow between injection and production wells by THM effects causes faster temperature drawdown and reduces energy production. The model also predicted fracture opening near injection well and closure at far field locations. We also simulated the aperture alteration for different joint stiffness, thermal expansion coefficients and rock matrix permeabilities. Increase in rock matrix permeability not only causes the leakage of injected water but also increases matrix contraction due to cooling and therefore the aperture growth. Additionally we reported the effect of thermo-poro-elastic deformation on the expansion and contraction of the formation for different reservoir properties. We established that in the early-stages the compaction/expansion of the formation was controlled by pore pressure change but in the late-stage it was controlled by thermal contraction.

Interest in geothermal energy production has grown rapidly in recent years due to the increasing demand for clean, renewable, domestic energy. Recent publications have suggested that geothermal energy from Enhanced Geothermal Systems could satisfy a large portion of the energy needs in the U.S. if the technology were implemented on a large scale. Pertinent to this goal are many of the lessons learned from the pioneering Hot Dry Rock project aimed at producing usable energy form the heat of the earth, conducted from 1970 to 1995 at Fenton Hill, New Mexico, USA. During this project, the Los Alamos National Laboratory created and tested two reservoirs at depths in the range of 2.8–3.5 km in crystalline rock formations underlying the Fenton Hill site. Thermal energies in the range of 3–10 MWt were produced demonstrating the technical feasibility of the concept. Many important lessons were learned regarding the creation, engineering and operation of such subsurface systems—these lessons will prove valuable as the geothermal community moves towards the goal of realizing the immense potential of this ubiquitous renewable energy resource. The purpose of this paper is to provide a brief, easy to read overview of this pioneering project.

Creation of an Enhanced Geothermal System relies on stimulation of fracture permeability through self-propping shear failure that creates a complex fracture network with high surface area for efficient heat transfer. In 2010, shear stimulation was carried out in well 27-15 at Desert Peak geothermal field, Nevada, by injecting cold water at pressure less than the minimum principal stress. An order-of-magnitude improvement in well injectivity was recorded. Here, we describe a numerical model that accounts for injection-induced stress changes and permeability enhancement during this stimulation. We use the coupled thermo-hydrological–mechanical simulator FEHM to (i) construct a wellbore model for non-steady bottom-hole temperature and pressure conditions during the injection, and (ii) apply these pressures and temperatures as a source term in a numerical model of the stimulation. A Mohr–Coulomb failure criterion and empirical fracture permeability is developed to describe permeability evolution of the fractured rock. The numerical model is calibrated using laboratory measurements of material properties on representative core samples and wellhead records of injection pressure and mass flow during the shear stimulation. The model captures both the absence of stimulation at low wellhead pressure (WHP ≤1.7 and ≤2.4 MPa) as well as the timing and magnitude of injectivity rise at medium WHP (3.1 MPa). Results indicate that thermoelastic effects near the wellbore and the associated non-local stresses further from the well combine to propagate a failure front away from the injection well. Elevated WHP promotes failure, increases the injection rate, and cools the wellbore; however, as the overpressure drops off with distance, thermal and non-local stresses play an ongoing role in promoting shear failure at increasing distance from the well.

Many technical, regulatory and public perception challenges remain to be addressed before large-scale deployment of CO 2 geologic storage becomes a reality. Two major risks associated with injection of CO 2 into the subsurface are the possibility of induced earthquakes compromising long-term seal integrity, and the displacement of saline brines resulting in contamination of shallow groundwater. Both induced seismicity and brine migration are caused by elevated pressures in the storage formation owing to the relative incompressibility of water. Here, we describe a strategy, termed passive injection that can be used to inject large amounts of CO 2 in a storage formation with no increase, temporary or long-term, in reservoir pressure. Passive injection relies on the strategic placement of brine production wells to create negative pressure gradients that result in CO 2 entering the formation at ambient pressure. Injection occurs at the intersection of pressure-depth profiles for a surface-pressurized, low-density CO 2 column and a hydrostatic column of formation fluid. A multi-stage, square-ring well configuration is envisaged, in which brine production wells are repurposed for CO 2 injection upon CO 2 breakthrough, and the next concentric ring of production wells installed at a greater distance. Numerical simulations of passive injection are presented using the coupled thermo-hydro-mechanical (THM), multi-fluid, multi-phase numerical simulator FEHM. We consider CO 2 injection into a 3 km-deep, closed reservoir over a period of 50 years, with up to four stages of injection and production depending on well-spacing and production pressures. Storage rates as high as 4 Mt yr −1 at 70% utilization of the reservoir pore volume are achieved under optimum conditions. Long-term mass production of brine is approximately 1.7 times that of CO 2 sequestered. Geomechanical effects due to reservoir drawdown, cooling near injection wells, and surface subsidence are modeled. The risk of induced seismicity is quantified in terms of the Coulomb Failure Stress (CFS) for an optimally oriented fault in an extensional tectonic regime. Injection and production-induced changes in pressure and CFS confirm that, both during and at the conclusion of injection, (i) reservoir pressure is everywhere less than or equal to its initial value; and (ii) the risk of induced seismicity is everywhere reduced or unchanged. Thus, the primary risks of brine migration outside the primary reservoir and induced seismicity compromising seal integrity are neutralized. Passive injection produces large quantities of brine, the treatment and disposal of which represents an additional economic burden to CO 2 geologic storage operations. Unless additional revenue streams or economies of scale can be leveraged, these costs are likely to limit the viability of the proposed scheme to only the most economically favorable sites.

We present the description of a fully coupled simulator FEHM for modeling coupled thermo-hydro-mechanical (THM) processes in geomedia. The coupled equations for fluid flow and energy transport are implemented using finite volume whereas Galerkin finite element method is used for mechanical force balance. The simulator is designed to address spatial scales on the order of tens of centimeters to tens of kilometers, and time scales on the order of hours to tens of years. The governing coupled nonlinear equations are solved using a Newton–Rapshon scheme with analytically or numerically computed Jacobians. A suite of models is available for coupling flow and mechanical deformation via permeability–deformation relationships. The coupled simulator is verified by comparing with several analytical solutions developed for this purpose. A subset of the simulator capabilities is benchmarked against commercially available simulators. We also demonstrate a good match with data from Desert Peak geothermal field in Nevada, USA. This validation required the use of a shear failure model with non-linear permeability–stress relationship. In addition, we present another application involving fluid injection into an inclined fault zone using a non-orthogonal grid with stress-dependent Young׳s modulus and permeability.

Heat extraction by cold water circulation disturbs the thermo-chemical equilibrium of a geothermal reservoir, activating the dissolution/precipitation of minerals in the fractures. Calcite being a more reactive mineral than other rock minerals composing the earth curst, we investigate the permeability alteration during geothermal heat production from carbonate reservoirs. In this study the simulations are performed using the code FEHM with coupled thermo-hydro-chemical (THC) capabilities for a three dimensional domain. The computational domain consists of a single fracture connecting the injection and production wells. For reactive alteration of aperture, the model considers that the kinetics of dissolution/precipitation is coupled to the equilibrium interactions among the aqueous species/ions. The reaction rate predominantly depends on the temperature dependent solubility and advective-dispersive solute transport in the fracture. Due to the nonuniform flow fields resulting from injection and production, the coupled thermo-hydro-chemical processes initiate significant variation of the aperture alteration rate over the fracture. We have considered different operating conditions such as different mass injection rate, injection temperature and concentration of minerals. Our simulations show that dissolution and precipitation can occur simultaneously at different locations in fracture. Furthermore the reaction rate varies with time and the reaction rate can also switch between dissolution and precipitation. To illustrate this interesting behavior, the variations of shape and size of zero reaction rate contours with time are shown. An interesting outcome is a non-monotonic evolution of the overall transmissivity between the wells. The alteration of overall transmissivity largely depends on the concentration of mineral in the injected water with respect to the solubility at the initial fracture temperature. For both dissolution and precipitation controlled cases, the rapid changes in transmissivity provide challenges for maintaining circulation of water at constant mass flow rate. � 2013 Elsevier Ltd.

Recent experiences with large-scale injection of fluids into geological formations within the Oil & Gas, Geothermal and Waste Disposal industries have demonstrated a risk of induced seismicity. In the case of geological sequestration of CO2, reactivation of faults may result in leakage pathways for the buoyant plume and thus compromise the integrity of seal formations. In this study, we investigate the potential for an overpressured reservoir formation to cause deformation and mechanical failure in an overlying, low-permeability caprock, thereby compromising seal integrity. In particular, we show that uplift and associated extensional strain in the caprock lead to a reduction in the minimum horizontal principal stress that reinforces the ambient extensional tectonic stress. Changes in the Coulomb failure stress (ΔCFS) characterize the tendency for fault failure. We use normalized and ΔCFS-weighted frequency distributions as an integrated measure of the 3-D distribution of ΔCFS. These measures quantify the magnitude and nature of the risk of induced seismicity. Using the example of the Springerville-St. Johns CO2 reservoir as an analogue site, we explore the sensitivity of the induced seismic risk to caprock stiffness, reservoir overpressure and well configuration. Over a range of these parameters, we calculate the geomechanical response of a large reservoir over a ten-year period of injection. The magnitude of induced stresses within the caprock is approximately 1–2 MPa for typical overpressures of 5–10 MPa, even in regions where the low-permeability caprock prevents appreciable increases in pore pressure. These stresses would be sufficient to cause reactivation of an undetected, well-oriented, critically stressed structure present above or near the injection location. Importantly, we show that this occurs outside a sphere of influence delineated by sub-surface pressure increase.

Assessment of potential CO 2 and brine leakage from wellbores is central to any consideration of the viability of geological CO 2 sequestration. Depleted oil and gas reservoirs are some of the potential candidates for consideration as sequestration sites. The sequestration sites are expected to cover laterally extensive areas to be of practical interest. Hence there is a high likelihood that such sites will contain many pre-existing abandoned wells. Most existing work on wellbore integrity has focused on field and laboratory studies of chemical reactivity. Very little work has been done on the impacts of mechanical stresses on wellbore performance. This study focuses on the potential enhancement of fluid flow pathways in the near-wellbore environment due to modifications in the geomechanical stress field resulting from the CO 2 injection operations. The majority of the operational scenarios for CO 2 sequestration lead to significant rise in the formation pore pressure. This is expected to lead to an expansion of the reservoir rock and build-up of shear stresses near wellbores where the existence of cement and casing are expected to constrain the expansion. If the stress buildup is large enough, this can lead to failure with attendant permeability enhancement that can potentially provide leakage pathways to shallower aquifers and the surface. In this study, we use a numerical model to simulate key features of a wellbore (casing, annulus and cement) embedded in a system that includes the upper aquifer, caprock, and storage aquifer. We present the sensitivity of damage initiation and propagation to various operational and formation parameters. We consider Mohr-Coulomb shear-failure models; tensile failure is also likely to occur but will require higher stress changes and will be preceded by shear failure. The modeling is performed using the numerical simulator FEHM developed at LANL that models coupled THM processes during multi-phase fluid flow and deformation in fractured porous media. FEHM has been developed extensively under projects on conventional/unconventional energy extraction

We present a preliminary model of geomechanical failure in wellbore systems induced by elevated pore- pressure following injection of CO 2 . The model is a coupled flow and geomechanics and operates on 2-D and 3- D detailed representations of the wellbore environment. We find that failure occurs at over-pressures of 6-7 MPa and that subsequent flow of water and/or CO 2 relieves pressure in the injection reservoir.

Results of drilling, logging, and testing of three exploration core holes, combined with results of geologic and hydrogeochemical investigations, have been used to present a reservoir model of the Platanares geothermal system, Honduras. Geothermal fluids circulate at depths ≥ 1.5 km in a region of active tectonism devoid of Quaternary volcanism. Large, artesian water entries of 160 to 165°C geothermal fluid in two core holes at 625 to 644 m and 460 to 635 m depth have maximum flow rates of roughly 355 and 560 l/min, respectively, which are equivalent to power outputs of about 3.1 and 5.1 MW(thermal). Dilute, alkali-chloride reservoir fluids (TDS ≤ 1200 mg/kg) are produced from fractured Miocene andesite and Cretaceous to Eocene redbeds that are hydrothermally altered. Fracture permeabillity in producing horizons is locally greater than 1500 and bulk porosity is ≤ 6%. A simple, fracture-dominated, volume-impedance model assuming turbulent flow indicates that the calculated reservoir storage capacity of each flowing hole is approximately 9.7 × 106 l/(kg cm−2), Tritium data indicate a mean residence time of 450 yr for water in the reservoir. Multiplying the natural fluid discharge rate by the mean residence time gives an estimated water volume of the Platanares system of ≥ 0.78 km3. Downward continuation of a 139°C/km “conductive” gradient at a depth of 400 m in a third core hole implies that the depth to a 225°C source reservoir (predicted from chemical geothermometers) is at least 1.5 km. Uranium-thorium disequilibrium ages on calcite veins at the surface and in the core holes indicate that the present Platanares hydrothermal system has been active for the last 0.25 m.y.